Viscoelastic surfactant fluids are normally made by mixing in appropriate amounts suitable surfactants such as anionic, cationic, nonionic and zwitterionic surfactants in an aqueous medium. The rheology of viscoelastic surfactant fluids, in particular the increase in viscosity of the solution, is attributed to the three dimensional structure formed by the components in the fluids. When the surfactant concentration significantly exceeds a critical level, and eventually subjected to the presence of an electrolyte, the surfactant molecules aggregate and form structures such as micelles that can interact to form a network exhibiting viscoelastic behavior. In the remaining part of this description, the term “micelle” will be used as a generic term for organized interacting species.
Viscoelastic surfactant solutions are usually formed by the addition of certain reagents to concentrated solutions of surfactants, frequently consisting of long-chain quaternary ammonium salts such as cetyltrimethylammonium bromide (CTAB). Common reagents that generate viscoelasticity in the surfactant solutions are salts such as ammonium chloride, potassium chloride, sodium salicylate and sodium isocyanate, and non-ionic organic molecules such as chloroform. The electrolyte content of surfactant solutions is also an important control on their viscoelastic behavior.
There has been considerable interest in using such viscoelastic surfactants in wellbore-service applications. Reference is made for example to U.S. Pat. Nos. 4,695,389, 4,725,372, 5,551,516, 5,964,295, and 5,979,557.
In treatments of subterranean formations, in particular hydraulic fracturing treatments, the total volume of fluid that needs to be pumped for completing the treatment is strongly influenced by the quantity of fluid lost to the surrounding matrix. In conventional fluids including polymers as viscosifying agents, during the initial phase of the treatment, the polymers are filtered at the rock face to form a polymer filter cake that subsequently inhibits further losses. However, VES-base fluids are polymer-free—which in itself is a major advantage since polymers, remaining in the matrix once the treatment is over, are a main source of formation damage—and consequently the fluid loss process is not governed by the filter-cake formation. Indeed, the rate of fluid flow through the rock is governed by a complex mixture of fluid rheology and fluid flow though the rock.
To overcome the tendency of high fluid loss in polymeric and VES-based fluids (in particular in hydraulic fracturing fluids and gravel carrier fluids), various fluid loss control additives have been proposed. Silica, mica, and calcite, alone, in combination, or in combination with starch, are known to reduce fluid loss in polymer-based fracturing fluids, by forming a filter cake on the formation face which is relatively impermeable to water, as described in U.S. Pat. No. 5,948,733. Use of these fluid loss control additives alone in a VES-based fluid, however, has been observed to give only modest decreases in fluid loss as described in U.S. Pat. No. 5,929,002, which is hereby incorporated by reference. The poor performance of these conventional fluid loss additives is typically attributed to the period of high leak-off (spurt) before a filter cake is formed and the formation of a filter cake permeable to the VES-based fluid.
Jones et al., UK Patent No. GB2,332,224, teaches the use of a wellbore service fluid for water control operations comprising a viscoelastic surfactant and very high concentrations of a cross-linkable water-soluble polymer and a cross-linking agent. Inorganic ions or polar organic molecules can be used as crosslinkers. The objective of the Jones patent is to enhance gel strength of the viscoelastic surfactant (VES)-based wellbore service fluid. Jones et al. does not discuss the use of such fluids to minimize fluid loss during drilling, drill-in, completion or stimulation.
Miller et al, in U.S. Patent Application No. 2002-0169085-A1, have found that adding small amounts of a crosslinker (typically in a concentration less than about 15 pounds per thousand gallons) and a crosslinkable polymer, to polymer free fluid results in effective fluid loss control.
Although the above-mentioned references have demonstrated the ability to control fluid loss by adding polymers or particulate solids to the VES fluid, such solutions inherently damage the permeability of the proppant pack at the end of treatment. Solid particulates are also difficult to meter and add on a continuous basis in field operations, and therefore, have received little field acceptance.
In low permeability media (typically less than approximately 2 mD), the viscosity of the treatment fluid and the compressibility of the reservoir fluids control the leak-off of the VES fluid. In medium to high permeability formations, increasing wellbore service fluid viscosity alone may not suffice to reduce fluid loss to practical levels. Although VES-based materials can be used alone, it would often be better to increase fluid loss control properties. Therefore, it would be desirable to have a VES-based treatment fluids comprising solid-free fluid loss control additives which reduce fluid loss, especially spurt, during treatment.